1. Field of the Invention
This invention relates to improvements in the sweetening of natural gas, and more particularly to a method and composition for sweetening natural gas in a treating tower, or in a pipe line, or at the well head or a collection point in the field, the composition being characterized by having a higher flash point and lower freezing point than other sweetening agents currently in use and better reaction rates.
2. Brief Description of the Prior Art
The production of natural gas often requires the separation or removal of various contaminants from the gas before it can be sent on for use. Natural gas often includes a substantial amount of entrained water and vaporized liquid hydrocarbons, usually the more volatile ones. Consequently the gas is subjected to treatment for separation of these components.
Natural gas may also contain gaseous impurities such as CO.sub.2 and H.sub.2 S which are acids in aqueous solution and thus corrosive. H.sub.2 S-containing gas is also highly toxic and malodorous and is referred to as "sour" gas. In fact, H.sub.2 S is more toxic than HCN and presents the problem that is highly malodorous at extremely low concentrations and tends to anesthetize the olfactory nerves with the result that a toxic exposure may not be recognized until it is too late. The removal or neutralization of H.sub.2 S is therefore a matter of necessity from a safety standpoint.
The removal of CO.sub.2 is not always required but can usually be removed by the other processes used to remove H.sub.2 S. In many processes of treatment, the chemicals used for sweetening react with both CO.sub.2 and H.sub.2 S and therefore the total amount of these impurities is used in calculating the amount of treating chemicals needed. In most procedures, the natural gas is first treated to remove water vapor and to separate condensable hydrocarbons or "condensate". The partial expansion of the gas through a choke to a lower pressure is effective to cool the gas sufficiently to remove both water and volatile hydrocarbons by condensing them from the gas stream. Often, there is material added, such as ethylene glycol, which will absorb or hydrate with the water to condense more readily from the gas stream. The expansion through the choke and consequent cooling is usually sufficient to condense the volatile liquid hydrocarbons which are recovered for use as solvents or fuel, i.e. casing head gasoline.
The technology known in the art for removing H.sub.2 S from raw natural gas was developed for large processing plants to remove H.sub.2 S in continuous processes. These large processing plants are fed by one or more natural gas wells, each of which may produce over 10 million cubic feet of natural gas per day. Many of these processes utilize commodity chemicals or proprietary materials to lower the H.sub.2 S levels in natural gas to pipeline specifications. Also, many of these processes not only sweeten sour natural gas to pipeline specifications, but also regenerate most, if not all, of the sweetening compositions involved.
A major process for removal of acid constituents from natural gas is one using an alkanolamine, such as monoethanolamine (MEA), diethanolamine (DEA), and/or triethanolamine (TEA). Treatment with alkanolamines involves circulating natural gas upward through a treatment tower to contact the alkanolamines. The acid gases react with the alkanolamines to form either a hydrosulfite or a carbonate of an alkanolamine. The alkanolamines admixed with the reaction products are conducted to a stripping still where the alkanolamines are removed and returned to the treatment column. The reaction products are then conducted to a reactor where they are heated sufficiently to reverse the process and regenerate the alkanolamines and release the acid gases which may be flared to convert H.sub.2 S to sulfur dioxide, or further reacted to form for solid disposal, or sent to a sulfur manufacturing plant.
There are several variations on the alkanolamine desulfurization process in use. One such process is Shell Sulfinol process (licensed by Shell) which utilizes a mixed solvent. The Sulfinol solvent is an admixture of sulfolane, water and diisopropanolamine (DIPA). Another process of this type utilizes a mixture of alkanolamines with ethylene glycol and water. This process combines the removal of water vapor, CO.sub.2 and H.sub.2 S.
Inorganic chemical-based systems, such as those containing nitrites, may also be used in scrubber towers. Although effective, such systems produce elemental sulfur solids. An example of such a system is marketed by NL Industries under the name "SULFACHECK" and disclosed in U.S. Pat. No. 4,515,759. "SULFACHECK" is a buffered aqueous solution of sodium nitrite which is injected into scrubber towers to sweeten natural gas. This solvent is designed for use in a one-step batch process, wherein the H.sub.2 S is removed from a raw natural gas stream through a reaction with the sodium nitrite.
Such inorganic chemical-based sweetening materials are undesirable since, as noted above, they produce significant solids (i.e., elemental sulfur). Accordingly, such systems cannot be used in "in-line" injection systems and may only be used in bubble towers. Moreover, such inorganic chemical-based sweetening systems are not regenerable, i.e., they must be used in a batch process.
Another process for removal of H.sub.2 S, uses a solid/gas chemical reaction. An iron sponge, consisting of hydrated iron oxide on an inert support, is treated with the sour gas where the iron oxide is converted to the sulfide. The iron sulfide can be reoxidized to the oxide with release of elemental sulfur. When the spent iron sulfide is removed from the tower and exposed to air, a pyrophoric conditions may exist.
Some physical processes are used for removal of CO.sub.2 and H.sub.2 S. Molecular sieves, i.e., zeolites and other materials having a pore size of molecular dimensions, which are specific in pore size for removal of CO.sub.2 and H.sub.2 S are used in the form of a bed through which the sour gas is passed. The bed is periodically regenerated by stripping with an inert gas. This process has the disadvantage present in most desulfurizing processes in that the separated H.sub.2 S or sulfur dioxide must be disposed of in the field.
The above desulfurization process have the disadvantage that reaction vessels, strippers, stills, separators and the like must be provided, which have a high capital cost. Also, these processes have the disadvantage that the current laws dealing with air pollution make it difficult to dispose of the separated H.sub.2 S or sulfur dioxide under field conditions.
There are several methods which have been developed for sweetening sour gas, i.e., for reducing the H.sub.2 S content of natural gas, continuously. For example, various chemicals may be added or injected "in-line" to natural gas pipelines. These sweetening products may be injected at the well head, separators, glycol units, coolers, compressors, etc., to provide contact with the natural gas. The natural gas industry has a great need for a satisfactory agent for sweetening sour (H.sub.2 S-containing) gases. An industrially satisfactory sweetening agent must not produce solids as the reaction product with the H.sub.2 S in the natural gas. The sweetening agent itself cannot be solid or particulate since it must be capable of in-line injection. Furthermore, the sweetening agent must be capable of reducing H.sub.2 S from levels of 1000 p.p.m or higher down to 4.0 p.p.m. or less, preferably down to essentially zero.
Materials used with such "in-line" injection systems include, e.g., various aldehydes. The H.sub.2 S reacts rapidly with the aldehyde compounds producing various types of addition products, such as polyethylene sulfide, polymethylene disulfide and trithiane. Such a process is disclosed, e.g., in Walker, J. F., Formaldehyde, Rheinhold publishing Company, New York, page 66 (1953).
Baize U.S. Pat. No. 4,748,011 discloses a method for the separation and collection of natural gas comprising the use of a sweetening solution. The sweetening solution consists of an aldehyde, a ketone, methanol, an amine inhibitor, sodium or potassium hydroxides and isopropanol. The amine inhibitor includes alkanolamines to adjust the pH.
Alkanolamines are also used to sweeten sour gas streams, e.g., in such "in-line" injection systems. Various alkanolamines may be used in such systems, e.g., monoethanolamine, diethanolamine, methyldiethanolamine and diglycolamine. For example, U.S. Pat. No. 2,776,870 discloses a process for separating acid components from a gas mixture comprising adding to the gas an absorbent containing water-soluble aliphatic amines and alkanolamines, preferably ethanolamine.
However, the alkanolamines are not selective in their reaction with H.sub.2 S. That is, alkanolamines absorb the total acid-gas components present in the gas stream, e.g., CO.sub.2, as well as H.sub.2 S. Such non-selectivity is not desirable in many applications and therefore, the usage of alkanolamines has also come under disfavor for this reason.
Dillon U.S. Pat. No. 4,978,512 discloses the use of a reaction product of a lower alkanolamine and (ii) a lower aldehyde (where the reactants are formaldehyde and ethanolamine the reaction product is predominately N,N' methylene bisoxazolidine; 1,3,5tri-(2-hydroxy-ethyl)-hexahydro-S-triazine; or a mixture thereof) as a sweetening agent. The product is a tertiary amine, i.e., triazine, rather than a secondary amine, is poisonous, and has substantial amounts of alcohols and free formaldehyde, both of which are environmentally unacceptable.
Weers European Patent 411,745 discloses contacting liquid hydrocarbons containing hydrogen sulfide, with the reaction product of certain alkylene polyamines and formaldehyde. The alkylene polyamine recited is in the form of a formula which includes ethylene diamine as the lowest member. However, none of the working examples include ethylene diamine as the reactant and the reaction conditions and the type of formaldehyde used are substantially different from the reaction conditions and reactants used in the present invention.
Moore U.S. Pat. No. 3,970,625 discloses that 35-50% aqueous formaldehyde is used in the Mannich reaction of urea with formaldehyde, which is substantially different from the reaction disclosed in the present invention.
The in-line treatments as described in Baize U.S. Pat. No. 4,748,011 and Dillon U.S. Pat. No. 4,978,512 are available commercially in the form of sweetening solutions which are supplied for in-line injection or for use in treating towers. These solutions, however, present potential safety, handling and environmental problems.
These solutions generally require the presence of a substantial amount of methanol to prevent freezing at moderate temperatures and therefore have flash points which are low enough to present hazards in handling. Also, the presence of unreacted formaldehyde is an environmental hazard. Consequently, there is a present need for a sweetening solution which is as effective as the Baize and Dillon solutions in treating sour natural gas which is non-foaming, free from solids, has a low freezing point and a higher flash point and is free from alcohols and unreacted formaldehyde.